Current Development of Ultra High Temperature Aqueous and Non-Aqueous Drilling Fluids.
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Transcript of Current Development of Ultra High Temperature Aqueous and Non-Aqueous Drilling Fluids.
![Page 1: Current Development of Ultra High Temperature Aqueous and Non-Aqueous Drilling Fluids.](https://reader036.fdocuments.in/reader036/viewer/2022062409/5697bfd31a28abf838cabf43/html5/thumbnails/1.jpg)
Current Development of Ultra High Temperature Aqueous and Non-Aqueous Drilling Fluids
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Outlines
IntroductionKey issueWeighting material affects ECDDevelopmental work and findings:
Emulsifiers Rheological modifiers and filtration control additives
Non-aqueous drilling fluid tested in HTHP viscometerSummary on non-aqueous drilling fluidAqueous drilling fluidSummary on aqueous drilling fluidQ&A
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Introduction
UHTHP = 200 to 250C with mud density > 1.75 SG.In 2007, Scomi Oiltools has consistently encountered high angle wells with bottom hole static temperature between 200 to 210C in the Gulf of Thailand.
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Key issue
When drilling reached TD, fluid in static condition
= more likely to cause problem.
When drilling to TD, fluid in dynamic condition
= less likely to cause problem.
Problems related to:Pressure management Induced factureBarite sag NPT during POOH
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Key issueFigure 2 – YP Response to Temperature in Dynamic
Condition with baseline YP at 49°C; BHST 210C
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Key issue
Figure 3 – YP Response to Temperature in Static Condition with baseline YP at 49°C; BHST 210C
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Weighting material affects ECD
Earlier lab work is based on API grade barite (4.2 SG).We are seeing the following weighing materials improve the rheology stability of the drilling fluid:
99.5% hematite. 98% ilmenite. 4.4+ SG barite.
Lower SG materials = higher impurities
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Weighting material affects ECD
Barite SG4.54.44.34.24.14.0
% Volume by SG % Weight by SGTable 1 - % of HGS and LGS in field barite
100%95%89%84%79%74%
HGS100%97%94%90%87%83%
HGSLGS LGS0% 0%5% 3%
11% 6%16% 10%21% 13%26% 17%
HGS = 4.5 SG
LGS = 2.6 SG
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Weighting material affects ECD
Barite TotalSG lb/bbl
4.5 6254.4 6294.3 6324.2 6364.1 6404.0 644
Table 2 – HGS and LGS in barite - 2.3 SG mud
HGSlb/bbl
625609592574555534
LGSlb/bbl
020406285110
HGS = 4.5 SG
LGS = 2.6 SG
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Selection of emulsifiers
Traditional emulsifiers package offered. Primary and secondary emulsifiers. Tall Oil Fatty Acid (TOFA) based.
Improvements in current available emulsifiers. Citric acid replaces fumaric/maleic acid. Tricarboxylic acid substituting a
dicarboxylic acid chain.Advantages of new emulsifiers.
Higher temperature stability. Improve rheological properties.
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Selection of emulsifiers
Table 3 - Emulsifier performance
Emulsifier DesignationP-S Pair
A B C D
Mud density, SG using API barite
2.1 to 2.2 to 2.2 to 2.2 1.5
Maximum stability - extended exposure, C
160 221 to 250 250+ 300
Termination - maleic anhydride or citric acid
maleic maleic maleic citric NA
Additive requirement for acid gas
Excess lime
Excess lime
Excess lime
Excess lime
None – stable
Control of progressive viscosity
Poor Good Good Excellen
tGood
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Rheological modifiers and filtration control additives
Table 4 - Viscosifiers and filtration control materials performance
Emulsifier DesignationP-S Pair
A B C D
Organophyllic hectorite - rheological additive, also improves filtration control. Extended temperature stability, to C
175 221221+
221+ Poor
Organophyllic bentonite - rheological additive, also improves filtration control. Temperature stability, to C
160 175 175 175 Poor
Liquid polymeric filtration control additive, C (often significant rheological effect)
175 221<25
0250+ 300
Synthetic copolymer filtration control additive, C
not useful
221<25
0250+ 300
Gilsonite - 450F version, lb/bbl 16+ 16+ 16+
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Non-aqueous drilling fluid tested in HTHP viscometerFigure 4 – Standard formulation synthetic based
mud1.92 SG 80/20 SBM Formulated with P&S, post 24h hot roll @ 200°CRheological Properties Reported by HTHP Viscometer
0
10
20
30
40
50
60
70
40 60 80 100 120 140 160 180 200 220 240Temperature - °C
Rheolo
gic
al valu
es -
cP
, lb
/100ft2 YP, lb/100ft2 6 RPM, ° 10min gel, lb/100ft2 100 RPM, °
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Non-aqueous drilling fluid tested in HTHP viscometer
Figure 5 – Special UHT Non-sag mud formulation 1.92 SG SBM Formulated with Emulsifier B, post 24h hot roll @ 200°C
Rheological Properties Reported by HTHP Viscometer
0
10
20
30
40
50
60
70
40 60 80 100 120 140 160 180 200 220 240Temperature - °C
Rheolo
gic
al valu
es -
cP
, lb
/100ft
2
YP, lb/100ft2 6 RPM, ° 10min gel, lb/100ft2 100 RPM, °
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Non-aqueous drilling fluid tested in HTHP viscometer
Figure 6 – Rheologically optimized mud formulation1.92 SG SBM Formulated with Emulsifier B1, post 24h hot roll @ 200°C
Rheological Properties Reported by HTHP Viscometer
0
10
20
30
40
50
60
70
40 60 80 100 120 140 160 180 200 220 240Temperature - °C
Rheolo
gic
al valu
es -
cP
, lb
/100ft
2
YP, lb/100ft2 6 RPM, ° 10min gel, lb/100ft2 100 RPM, °
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Summary on non-aqueous fluid
Weighting material Important to source quality material to
reduce contaminants.New improved emulsifier
Higher temperature stability. Better control of progressive rheology. Enhances temperature stability of other
mud components.
Aqueous Drilling Fluid
Better pressure management and prevention sag
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Aqueous drilling fluid
UHTHP aqueous drilling fluidSimilar problems associated with barite sag and pressure management.Limitations:
Degradation of polymer. Flocculation of drill solids.
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Aqueous drilling fluid – Degradation of polymer
Figure 7 – Thermal degradation of two polymeric UHTHP filtration control materials for aqueous
drilling fluid
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Aqueous drilling fluid – Flocculation of drill solids
Available low molecular weight dispersants are effective.
Start fresh drilling fluid with low LGS. Maintain minimum drill solids contamination.
Flocculation of drill solids
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Summary on aqueous drilling fluid
UHT polymeric viscosifier Capable to function as viscosifier and
filtration control additive. Higher temperature stability.
Low molecular weight dispersant Effective at low LGS contamination.
Contamination Start drilling fluid with minimum LGS. Maintain minimum drill solids in fluid.